In petroleum production, completion is the process of making a well ready for production or injection. This principally involves preparing the bottom of the hole to the required specifications, running the production tubing and associated down hole tools, as well as perforating and/or stimulating the well as required. Sometimes, the process of running and cementing the casing is also included.
Lower completion refers to the portion of the well across the production or injection zone, beneath the production tubing. A well designer has many tools and options available to design the lower completion according to the conditions of the reservoir. Typically, the lower completion is set across the production zone using a liner hanger system, which anchors the lower completion equipment to the production casing string.
Upper completion refers to all components positioned above the bottom of the production tubing. Proper design of this “completion string” is essential to ensure the well can flow properly given the reservoir conditions and to permit any operations deemed necessary for enhancing production and safety.
In cased hole completions, which are performed in the majority of wells, once the completion string is in place, the final stage includes making a flow path or connection between the wellbore and the formation. The flow path or connection is created by running perforation guns into the casing or liner and actuating the perforation guns to create holes through the casing or liner to access the formation. Modern perforations can be made using shaped explosive charges.
Sometimes, further stimulation is necessary to achieve viable productivity after a well is fully completed. There are a number of stimulation techniques which can be employed at such a time.
Fracturing is a common stimulation technique that includes creating and extending fractures from the perforation tunnels deeper into the formation, thereby increasing the surface area available for formation fluids to flow into the well and avoiding damage near the wellbore. This may be done by injecting fluids at high pressure (hydraulic fracturing), injecting fluids laced with round granular material (proppant fracturing), or using explosives to generate a high pressure and high speed gas flow (TNT or PETN, and propellant stimulation).
Hydraulic fracturing, often called fracking, fracing or hydrofracking, is the process of initiating and subsequently propagating a fracture in a rock layer, by means of a pressurized fluid, in order to release petroleum, natural gas, coal steam gas or other substances for extraction. The fracturing, known colloquially as a frack job or frac job, is performed from a wellbore drilled into reservoir rock formations. The energy from the injection of a highly pressurized fluid, such as water, creates new channels in the rock that can increase the extraction rates and recovery of fossil fuels.
The technique of fracturing is used to increase or restore the rate at which fluids, such as oil or water, or natural gas can be produced from subterranean natural reservoirs, including unconventional reservoirs such as shale rock or coal beds. Fracturing enables the production of natural gas and oil from rock formations deep below the earth's surface, generally 5,000-20,000 feet or 1,500-6,100 meters. At such depths, there may not be sufficient porosity and permeability to allow natural gas and oil to flow from the rock into the wellbore at economic rates. Thus, creating conductive fractures in the rock is essential to extract gas from shale reservoirs due to the extremely low natural permeability of shale. Fractures provide a conductive path connecting a larger area of the reservoir to the well, thereby increasing the area from which natural gas and liquids can be recovered from the targeted formation.
Pumping the fracturing fluid into the wellbore, at a rate sufficient to increase pressure downhole, until the pressure exceeds the fracture gradient of the rock and forms a fracture. As the rock cracks, the fracture fluid continues to flow farther into the rock, extending the crack farther. To prevent the fracture(s) from closing after the injection process has stopped, a solid proppant, such as a sieved round sand, can be added to the fluid. The propped fracture remains sufficiently permeable to allow the flow of formation fluids to the well.
The location of fracturing along the length of the borehole can be controlled by inserting composite plugs, also known as bridge plugs, above and below the region to be fractured. This allows a borehole to be progressively fractured along the length of the bore while preventing leakage of fluid through previously fractured regions. Fluid and proppant are introduced to the working region through piping in the upper plug. This method is commonly referred to as “plug and perf.”
Typically, hydraulic fracturing is performed in cased wellbores, and the zones to be fractured are accessed by perforating the casing at those locations.
While hydraulic fracturing can be performed in vertical wells, today it is more often performed in horizontal wells. Horizontal drilling involves wellbores where the terminal borehole is completed as a “lateral” that extends parallel with the rock layer containing the substance to be extracted. For example, laterals extend 1,500 to 5,000 feet in the Barnett Shale basin. In contrast, a vertical well only accesses the thickness of the rock layer, typically 50-300 feet. Horizontal drilling also reduces surface disruptions, as fewer wells are required. Drilling a wellbore produces rock chips and fine rock particles that may enter cracks and pore space at the wellbore wall, reducing the porosity and/or permeability at and near the wellbore. The production of rock chips, fine rock particles and the like reduces flow into the borehole from the surrounding rock formation, and partially seals off the borehole from the surrounding rock. Hydraulic fracturing can be used to restore porosity and/or permeability.
Conventional lateral wells are completed by inserting coiled tubing or a similar, generally flexible conduit therein, until the flexible nature of the tubing prevents further insertion. While coil tubing does not require making up and/or breaking out each pipe joint, coiled tubing cannot be rotated, which increases the likelihood of sticking and significantly reduces the ability to extend the pipe laterally. Once a certain depth is reached in a highly angled and/or horizontal well, the pipe essentially acts like soft spaghetti and can no longer be pushed into the hole. Coiled tubing is also more limited in terms of pipe wall thickness to provide flexibility thereby limiting the weight of the string.
Conventional completion rigs include a mast, which extends upward and slightly outward typically at approximately a 3 degree angle from a carrier or similar base structure. The angled mast provides that cables and/or other features that support a top drive and/or other equipment can hang downward from the mast, directly over a wellbore, without contacting the mast. For example, most top drives and/or power swivels require a “torque arm” to be attached thereto, the torque arm including a cable that is secured to the ground or another fixed structure to counteract excess torque and/or rotation applied to the top drive/power swivel. Additionally, a blowout preventer stack, having sufficient components and a height that complies with required regulations, must be positioned directly above the wellbore. A mast having a slight angle accommodates for these and other features common to completion rigs. As a result, a rig must often be positioned at least four feet, or more, away from the wellbore depending on the height of the mast. A need exists for systems and methods having a reduced footprint, especially in lucrative regions where closer spacing of wells can significantly affect production and economic gain, and in marginal regions, where closer spacing of wells would be necessary to enable economically viable production.
Prior to common use of coiled tubing, completion operations often involved the use of workover/production rigs for insertion of successive joints of pipe, which must be threaded together and torqued, often by hand, creating a significant potential for injury or death of laborers involved in the completion operation, and requiring significant time to engage (e.g., “make up”) each pipe joint. Drilling rigs could also be utilized to run production tubing but are more expensive although the individual joints of pipes result in the same types of problems.
A significant problem with prior art production/workover rigs or drilling rigs as opposed to coiled tubing units is that individual production tubing pipe connections are often considerably more difficult to make up and/or break out than the drilling pipe connections. Drilling pipe connections are enlarged and are designed for quick make up and break out many times with very little concern about exact alignment of the connectors. Drill pipe is designed to be frequently and quickly made up and broken out without being damaged even if the alignment is not particularly precise. On the other hand, production tubing is normally intended for long term use in the well and requires much more accurate alignment of the connectors to avoid damaging the threads. Production tubing does not typically utilize the expensive enlarged connectors like drill pipe and, in some completions, enlarged connectors simply are not feasible due to clearance problems within the wellbore. Thus, especially for production tubing, prior art workover/production rigs are much slower for inserting and/or removing production tubing pipe into or out of the well than coiled tubing units and are more likely to result in operator injuries and errors during pipe connection make up and break out than coiled tubing. There are also problems with human error in aligning the individual production tubing connectors whereby cross-threading could result in a damaged or leaking connection.
Prior art insertion techniques of completion tubing into a lateral well therefore suffers from significant limitations including but not limited to: 1) the longer time required to run tubing into a well; 2) operator safety; and 3) the maximum horizontal distance across which the tubing can be inserted is limited by the nature of the tubing used and/or the force able to be applied from the surface. Generally, once the frictional forces between the lateral portion of the well and the length of tubing therein exceed the downward force applied by the weight of the tubing in the vertical portion of the well, further insertion becomes extremely difficult, if not impossible, thus limiting the maximum length of a lateral.
Due to the significant day rates and rental costs when performing oilfield operations, a need exists for systems and methods capable of faster, yet safer insertion of pipe and/or tubing into a well. Additionally, due to the costs associated with the drilling, completion, and production of a well, a need exists for systems and methods capable of extending the maximum length of a lateral, thereby increasing the productivity of the well.
Hydraulic fracturing is commonly applied to wells drilled in low permeability reservoir rock. An estimated 90 percent of the natural gas wells in the United States use hydraulic fracturing to produce gas at economic rates.
The fluid injected into the rock is typically a slurry of water, proppants, and chemical additives. Additionally, gels, foams, and/or compressed gases, including nitrogen, carbon dioxide and air can be injected. Various types of proppant include silica sand, resin-coated sand, and man-made ceramics. The type of proppant used may vary depending on the type of permeability or grain strength needed. Sand containing naturally radioactive minerals is sometimes used so that the fracture trace along the wellbore can be measured. Chemical additives can be applied to tailor the injected material to the specific geological situation, protect the well, and improve its operation, though the injected fluid is approximately 99 percent water and 1 percent proppant, this composition varying slightly based on the type of well. The composition of injected fluid can be changed during the operation of a well over time. Typically, acid is initially used to increase permeability, then proppants are used with a gradual increase in size and/or density, and finally, the well is flushed with water under pressure. At least a portion of the injected fluid can be recovered and stored in pits or containers; the fluid can be toxic due to the chemical additives and material washed out from the ground. The recovered fluid is sometimes processed so that at least a portion thereof can be reused in fracking operations, released into the environment after treatment, and/or left in the geologic formation.
Advances in completion technology have led to the emergence of open hole multi-stage fracturing systems. These systems effectively place fractures in specific places in the wellbore, thus increasing the cumulative production in a shorter time frame.
Those of skill in the art will appreciate the present system which addresses the above and other problems.
The above general description and the following detailed description are merely illustrative of the generic invention, and additional modes, advantages, and particulars of this invention will be readily suggested to those skilled in the art without departing from the spirit and scope of the invention.